The statements in this section merely provide background information related to the present disclosure and may not constitute prior art.
This disclosure relates to compositions and methods for treating subterranean formations, in particular, compositions and methods for cementing subterranean wells.
Portland cement systems for well cementing are routinely designed to perform at temperatures ranging from below freezing in wells involving permafrost zones to 350° C. in geothermal and thermal-recovery wells. Well cements encounter the pressure range from near ambient in shallow wells to more than 200 MPa in deep wells. In addition to severe temperatures and pressures, well cements must often be designed to contend with weak or porous formations, corrosive fluids and overpressured formation fluids. Cement additives make it possible to accommodate such a wide range of conditions. Additives modify the behavior of the cement system, ideally allowing successful slurry placement, rapid strength development and adequate zonal isolation throughout the lifetime of the well.
Today more than 100 additives for well cements are available, many of which may be supplied in solid or liquid forms. A thorough presentation of cement additives for well cementing may be found in the following publication: Nelson E B, Michaux M and Drochon B: “Cement Additives and Mechanisms of Action,” in Nelson E B and Guillot D (eds.): Well Cementing, 2nd Edition, Schlumberger, Houston (2006) 49-91. The present document is concerned with additives that control the rate at which Portland cement slurries hydrate, set and develop strength.
Portland-cement hydration comprises exothermic reactions; therefore, the hydration rate may be measured by an isothermal conduction calorimeter. Heat flow is recorded as a function of time. Faster hydration is indicated by higher heat flow. Portland cement hydration is arbitrarily defined by five stages. Stage I, the preinduction period, begins as the Portland-cement powder is mixed with water. The duration is short—on the order of a few minutes. A large exotherm is observed resulting from the wetting of the powder and the rapidity of the initial hydration reactions. Stage II, the induction period, is a period during which cement hydration slows temporarily. In the context of well cementing, pumping of the slurry occurs during the induction period. Stage III, the acceleration period, is the time at which the slurry begins to set and develop strength. Hydration is more intense as evidenced by the higher heat flow. Eventually a continuous layer of hydrates forms around the cement particles. The layer thickens with time and the hydration rate is controlled by diffusion of water and ions through the layer. This marks the beginning of Stage IV, the deceleration period, during which strength development continues. Stage V, the diffusion period, is characterized by continued hydration at a slow pace. Further details about the chemistry of Portland cement hydration may be found in the following publication: Nelson E B and Michaux M: “Chemistry and Characterization of Portland Cement,” in Nelson E B and Guillot D (eds.): Well Cementing, 2nd Edition, Schlumberger, Houston (2006) 23-48.
Cement retarders are generally used when the cement slurry is exposed to a high-temperature environment. The role of the retarder is to lengthen the thickening time, giving the operator sufficient time to properly place the cement slurry in the well. Therefore, retarders extend the induction period and often decrease the intensity of the acceleration period. Common retarders include lignosulfonates, hydroxycarboxylic acids, saccharides, cellulose derivatives and/or organophosphonates.
The depths of many oil and gas wells may be several thousand meters. Due mainly to the geothermal gradient, bottomhole temperatures of these wells may exceed 260° C. (500° F.). Cementing at such high temperatures requires particularly powerful cement retarders; otherwise, the cement slurry may thicken and set prematurely. The magnitude of the challenge may be illustrated by the fact that, at such high temperatures, the thickening time of a cement slurry usually decreases by about 50% for every 14° C. (25° F.) increase in bottomhole circulating temperature (BHCT).
Recently, operators have begun to drill oil and gas wells with even higher bottomhole temperatures. In response, the well-cementing industry has been challenged to provide retarders that can function at temperatures and pressures as high as 316° C. (600° F.) BHCT.
The formation pressure is generally very high in deep wells—up to about 241 MPa (35,000 psi). To maintain well control and prevent formation-fluid invasion, the hydrostatic pressure of the cement-slurry column in the well must be higher than that of the formation. Thus, the cement-slurry density frequently exceeds 2160 kg/m3 (18 lbm/gal), and may be as high as 2760 kg/m3 (23 lbm/gal). Such high densities are achieved by adding weighting agents to the cement slurry. Common weighting agents include hematite, ilmenite, barite and/or manganese tetraoxide. For adequate pumpability and placement, the cement slurry must have acceptable rheological properties. The presence of weighting agents poses a challenge in this respect, and cement dispersants are frequently included in the slurry. In addition, the particle sizes of the cement-slurry solids may be optimized to minimize the slurry viscosity, yet avoid particle settling and sedimentation. The optimized-particle-size concept is exemplified by CemCRETE™ concrete-based oilwell cementing technology, available from Schlumberger.
In such cases, it would be preferable if other additives such as retarders do not increase the slurry viscosity. Indeed, it would be particularly preferred if the retarders had a dispersing effect in addition to their ability to control cement hydration.
For many years, organophosphonate-base retarders have been particularly useful when cementing wells with BHCTs higher than about 150° C. (300° F.). These retarders are often accompanied by borate salts (e.g., sodium tetraborate, sodium pentaborate, boric acid, or potassium pentaborate). However, these systems alone are usually difficult to use at BHCTs higher than about 250° C. (482° F.). The temperature range may be extended to about 288° C. (550° F.) by adding a copolymer of AMPS (2-acrylamido-2-methylpropane-3-sulfonic acid) and acrylic acid or acrylamide. Such copolymers are better known as fluid-loss-control additives.
However, despite the valuable contributions of the prior art, extending the practical temperature range of organophosphonate/borate retarders beyond about 288° C. has remained an elusive goal.